Shale hydration inhibitors for clear water drilling fluids



ited States 3,617,351 Patented Jan. 16, 1962 3 017 ,351 SHALE HY DRATION INHIBITORS FOR CLEAR WATER DRILLING FLUIDS Platho P. Scott, Jra, Duane B. Anderson, and Arthur Park,

Tulsa, Okla, assignors to Pan American Petroleum Corporation, Tulsa, Okla, a corporation of Delaware N Drawing. Filed Nov. 6, 1958, Ser. No. 772,164

11 Claims. (Cl. 252-85) This invention relates to the drilling of wells. More particularly, it relates to drilling operations in which a fast chilling rate is obtained by the use of substantially clear, solids-free water as a drilling fluid.

Many wells are now drilled in which the solids content of the drilling fluid is maintained at as low a value as possible. The principal advantages are a faster drilling rate, increased bit life, and decreased drilling fluid costs. One of the disadvantages is an increased tendency of shale to slough off the walls of the hole and fall down the well. If such sloughing occurs while the drill string is in the well, the bit may be stuck in the hole. If sloughing occurs during a trip to change bits, the hole may fill up several hundred feet with shale, which must be cleared from the well before drilling can proceed.

Some of the shale which falls down the well is simply bit cuttings which have become lodged in enlarged sections of the hole. These are often dislodged from time to time by the drilling operations. They are more frequently knocked into the hole when the bit is pulled out of the well or is run back into the well. This action is not really true shale sloughing, but produces the same effects.

Part of the actual shale sloughing may be due to mechanical stresses in the shale around the well. Much of the shale sloughing, however, is due to penetration into the shale of the water used as a drilling fluid. This water soaks the shale, causing it to soften and often to swell. The soft, swollen shale then either falls or is easily knocked into the well. Thus, shale sloughing is seen to have two causes. One is of a mechanical nature. The other, the action of water on the shale, may be termed chemical in nature.

An object of this invention is to decrease the sloughing of the shale into wells drilled with substantially clear water. A more specific object is todecrease the softening and swelling of shale due to the action of water on the shale. An additional object is to decrease the softening action of water on bit cuttings so these cuttings will not break apart so badly and can be more easily removed from the water in the mud pits at the surface.

We have now found that we can substantially eliminate the shale sloughing due to the softening and swelling action of water by use of a combination of three, and preferably four, additives in the water. A preferred drilling fluid contains the following ingredients in addition to water.

Ammonium sulfate lbs./bbl 10.0 Intracol OA lb./bbl 0.5 Separan 2610 lb./bbl 0.02 Oil gal./bbl 0.5

All the concentrations are in terms of weight or volume per 42-gallon barrel of water. lntracol 0A is an amide of a fatty acid and a polyamine which has been made more water soluble by forming the acetate salt. Separan 2610 is an acrylami'de polymer hydrolyte.

If water-sensitive shale is soaked in water, the shale will swell. For example, when a sample of the shale of the Labette shale series of Pennsylvanian age outcropping east of Tulsa,-Oklahoma, is ground to pass an 80 mesh screen, agitated in water in a graduated cylinder, and

allowed to stand for 24 hours, the volume increases to about 14 percent greater than the volume of the same weight of shale mixed into diesel Oil.

A more striking demonstration can be made by casting a block of the shale in cement such as calcium sulfate after coating the block with plastic to prevent effects of the water of the cement slurry. After the cement is set, holes are drilled in the shale block using a tri-cone roller bit such as those normally used in drilling oil wells. Water is circulated through the bit as a drilling fluid. After the holes are drilled, they are filled with water and allowed to stand. After 24 hours it will be found that the shale has sloughed into the holes and the block of shale will have expanded with such force that the cement case around the shale block will be split apart.

We have found that, if a water-soluble potassium or ammonium salt is added to the drilling water in an amount equal to about 10 pounds of the salt per barrel of water, the powdered shale will not expand in the test in the graduated cylinder. The shale block cast in cement will not expand and burst the case. Neither will the shale in the presence of the potassium or ammonium salts slough into the holes drilled into the block of shale.

' It will be apparent that the addition of a suflicient quantity of ammonium or potassium salts-to substantially clear water used in drilling wells will prevent swelling of the shale and will, consequently, decrease the tendency of the shale to slough into the well. Accordingly, use of ammonium and potassium salts in clear water permits clear water drilling operations to be extended to many areas in which such operations are not now possible due to shale sloughing difliculties. These salts also permit using clear water to drill deeper in many wells before sloughing due to mechanical causes requires converting to clay-containing drilling fluids.

We have also found that, while use of ammonium and potassium salts in clear water offers a considerable improvement over use of clear water alone, the salts do not offer a complete solution to the problem. For example, if water-sensitive shale cuttings are placed in a jar with water and the jar is rolled for 18 hours, the cuttings will be found to have broken up considerably. The addition of ammonium or potassium salts to the water does not prevent this breakage. When certain amines are added to the water, however, thebreakage of cuttings is greatly decreased. We believe this is due to adsorption of amines on the shale particle surfaces resulting in the formation of a hydrophobic protective film around each particle. This film prevents soaking of the water into the shale particle and hence prevents softening of the particle. The ammonium and potassium salts, on the other hand, do not form a protective adsorbed film. Thus, water containing these salts but no amines soaks into the shale particles and softens them. .The particles do not swell, but they do soften. The softened particles are then easily broken by mechanical action.

In a well this means that, if water containing ammonium or potassium salts is used as a drilling fluid, the shale will not swell and be pushed into the well by a swelling action. It also means, however, that the shale will be'so-ftened so that mechanical causes, such as overburden pressure, operation of the drill string in the well, or the like, can more easily knock the softened shale'into the well.

Since certain amines or water-soluble salts thereof can prevent softening of the shale, we prefer to include a small amount of such amines in substantially clear water used as a drilling fluid. It is true that, as water penetrates from the well into the shale, the amine is adsorbed onto the shale surfaces and is lost from the water in a zone within a few inches of the well. Sometimes all the amine is lost within the first inch. This is still a considerable advantage, however, since a strong ring of amine-coated shale is established adjacent the well. This strong ring affords considerable mechanical protection to any softened shale behind the ring.

One additional advantage of using the amines is their protective action on bit cuttings. In drilling with substantially clear water, the bit cuttings tend to rise much more slowly up the well than when a regular clay drilling fluid is used. This is due to the lower viscosity, gel strength, and density of the clear water. Because of the slower rate of rise of the cuttings, there is a much greater tendency to disintegrate and break down into very finely divided material. This is objectionable, not only from the standpoint of the geologist who studies the cuttings, but also to the driller who finds it more difficult to remove fine particles than coarse particles from the water. As previously noted, the amines greatly decrease the tendency of the particles to soften and break apart. Thus, these amines tend to increase the size of bit cuttings recovered at the surface.

We have found that additional improvement in operations can be achieved by adding a fluid loss reducing material to the water containing the ammonium or potassium salt and the amine. In drilling with clear water a flocculating agent is ordinarily added to the water as it leaves the well and enters the settling pits to cause the bit cuttings and dispersed clays to settle rapidly to the bottom of the pits. The agent most commonly used for this purpose is Separan 2610. This is a trade-mark of the Dow Chemical Company for an acrylamide polymer hydrolyte having from about to 120 amide groups for each carboxyl group and having a viscosity of at least about 4 centipoises for a 0.5 percent by weight solution of the hydrolyte. If Separan is added to the water as it is pumped down the well, it has been found that the rate of loss of fluid to formations being drilled can be considerably decreased. This discovery is described in more detail and is claimed in U.S. patent application S.N. 715,494, filed on February 17, 1958, by Julius P. Gallus.

The Separan seems to serve not only as a fluid loss reducing agent, but also produces, in combination with the ammonium or potassium salt and a certain class of amines, a considerably increased protective action on shales contacted by water. That is, in the test previously described in which shale particles are rolled in a jar with water containing various additives, less of the shale particles tend to break apart in the presence of the combination of the three materials. A possible explanation is that the Separan decreases the entry of water into the shale particles and also assists the amine in forming a protective coating over the particles.

In the well the Separan performs the same functions on the well wall. Thus, less water penetrates through the zone of shale coated with amine so there is decreased volume of softened shale behind the amine-coated section. In addition, the Separan further strengthens the amine-coated ring of shale adjacent the well.

As might be expected, the water containing rather high concentrations of ammonium or potassium salts is somewhat corrosive. The amines tend to decrease the rate of corrosion to some extent. We have now found that the ability of the amines to decrease the corrosion rate can be greatly enhanced by the addition of a small volume of mineral oil to the water containing the amine and salt. We have discovered that the oil, like the Separan, also assists the amine in protecting shale cuttings from the action of water. For example, in the test in which shale particles are rolled in the jar with water, only about 2 percent of the shale particles broke apart seriously when the water contained a little oil in addition to the ammonium salt, amine, and Separan.

The nature, required concentration, and function of the various components of our composition can be better understood by consideration of the following data which,

for purposes of convenience, are presented in the form of examples.

EXAMPLE 1 To determine the abilities of various chemicals to decrease the swelling action of hydratable shales, a sample of Labette shale was powdered to pass an mesh U.S. standard sieve. Samples weighing 20 grams were immersed in solutions, agitated, and then allowed to set for 24 hours in graduated cylinders. The volume of the settled solids was then measured. The difference between the volume of the shale immersed in diesel oil and the volume in various solutions indicated the amount of expansion or swelling. Results of these tests are reported in Table A.

Table A Additive Test Change in Volume of No. Concentra- Shale (Percent) Nature tion (lbs./

bbl.)

1 Diesel oil only 0. 2 Tap water +14. 3 Ammonium sulphat 1. 40 +12. 4 0 2.80 +5. 5 4. 20 +2. 6 5. 00 +2. 7-.-.. (1 111:014 +2. 8. Ammonium sulphate 5. 60 +10.

Nalcamine G30 1.00 Separan 0.02 9- Ammonium sulphate 11.00 +2.

Nalcamine G30. 1.00 Separan 0.02 10- Potassium Dichromate.... 1. 40 +14. 11--. .....do 5.60 +2. 12.... o 20.00 -2. l3. Sodium chloride.. 4. 20 +14. 14.- Sodium chloride.... 11.00 +11.

Nalczmine G30. 1.00 V Separan. 0. 02

15. Manganese chloride 20. 00 +11 16-... Sodium chloride.-. 20.00 +7. 17. Magnesium sulphate. 19. 00 +9. 18. Ammonium chloride 20.00 +2. 19. Potassium ferrocyanide. 20.00 2. 20. Sodium chloride 17.00 +2.

Ammonium sulphate. 17.00 21--.. Sodium chloride 8.00 +2 Ammonium sulphate. 8.00 22. Calcium chloride 5.00 +2.

Ammonium sulphate. 11.00 Nalcamine G30. 0.50 Separan 0, 2 23. Intracol 0A.-. 0v 50 +8. 24.-.. Intracol 0A... 0. 50 +14.

Separan 0.02 25--.. Ammonium sulphate. 5. 60 +2.

Intracol 0. 50 Separan 0.02 26. Ammonium sulpha 10.00 1.

Intracol 0A.... 0.50 Separan 0.02 27. Ammonium sulphate 15.00 1.

lntracol 0.50 Separan 0.02 28--.. Calcium chloride... 20.00 +9. 29.-.. Water only +5 (Morrow shale). 30. Diesel oil 0 (Morrow shale). 31- Ammonium sulpha 0 (Morrow shale).

Intracol 0A.-. Separan...-. 32.-.. Water only. +25 (Cherokee shale). 33.... Diesel oil 0 (Cherokee shale). 34- Ammonium sulphate 10.00 +8 (Cherokee shale).

ac 0.50 Se aran 0.02 35--.. Ammonium sulphate 10.00 1. Intracol 0A 0.50 Separan.-. 0.02 Diesel oil 0.5 glaili/ 36.-.. Ammonium sulphate 10.00 1 (Test conducted at 200 F.). Intracol 0A 0.50 Separan. 0.02 Diesel oil 0.5 gal./ bbl.

In the table, Nalcamine G30 is a trademark of National Aluminate Corporation for a substituted imidazoline having the formula 1-(Z-aminoethyl)-2-methyl-2-imidazoline.

Separan is Separan 2610, which has been previously defined. Intracol 0A is a trademark of Synthetic Chemicals, Inc., for the acetic acid salt of the oleic acid amide of polyethylene diamine. It has multiple amine groups.

Tests 3 to 7 and to 12 indicate that the ammonium or potassium salt should be present in an amount of at least about 3 pounds per barrel of water if shale swelling is to be effectively decreased. Tests 8 and 9 indicate that in the presence of amines such as Nalcamine G30, however, an even higher concentration of ammonium or potassium salt should be used. Preferably, the concentration should be about 10 pounds per barrel. Tests 13, 14 and 16 demonstrate the relatively small effectiveness of sodium chloride in preventing the swelling of clay. Tests 15, 17 and 28 show that the alkaline earth metal salts are not at all comparable to ammonium and potassium salts. Tests 18 and 19 demonstrate the elfectiveness of salts of ammonium and potassium other than the sulfates and dichromates. This seems to demonstrate that the action is due to the cation of the salt. Thus, it would seem that any water-soluble potassium or ammonium salt can be used. In his connection the term water-soluble salt means one which is soluble at least to the extent of the minimum concentration of 3 pounds per barrel of water.

We belive the explanation to be that the volumes of the hydrated ammonium and potassium ions are considerably smaller than the volumes of more highly hydrated ions such as sodium, calcium, and the like. To determine if the presence of sodium and calcium ions in oil field brines might interfere with the action of the ammonium and potassium salts, tests 20 to 22 were run. The results indicate that swelling of shale can be effectively prevented by ammonium sulphate even in the presence of an equal concentration of sodium chloride. A fairly high concentration of calcium chloride also failed to affect adversely the swelling inhibiting action of ammonium sulphate. This is very advantageous since it permits drilling salt sections with brines substantially saturated with sodium and calcium chloride. This prevents dissolving of the salt by the water used as a drilling fluid. Test 23 shows that Intracol CA has some inhibiting action on the swelling of shale. In the presence of a small amount of Separan, however, the action appears to be substantially lost. Tests 25, 26 and 27 demonstrate the highly effective nature of the preferred combination of additives for preventing sloughing of shale in clear water drilling.

Tests 29 and 31 show the effectiveness of the preferred combination of additives on a shale other than the Pennsylvanian shale used in most of the tests. Tests 32 to 34 show the effects of the additives on still another shale. It will be noted that the degree of swelling in the presence of the additives is somewhat greater with this shale than with the Labette shale. This is to be expected since the swelling of the Cherokee shale in the presence of water demonstrates that it is much more susceptible to hydration and swelling than the Pennsylvanian shale. Test 35, when compared to test 26, shows that the presence of diesel oil has no adverse efiects. Test 36 Was conducted at 200 F. The results show that the additives do not lose their effectiveness at elevated temperature.

EXAMPLE 2 To determine the abilities of various materials to prevent softening of shale by water, 50 gram samples of Labette shale were placed in pint jars with 350 milliliters of water containing the additive to be tested. The jars were then rolled for 18 hours. The shale placed in the jars had been ground and screened. All particles passed a number 4 sieve and were retained on a number 10 sieve, U.S. standard series. After rolling, the Water suspension of shale was poured through a number 30 sieve. This sieve had openings about the same as those in many drilling fluid shale shakers. The shale retained on this screen was dried and weighed to determine the percent which resisted deterioration to such a degree that it would not pass through the screen. The results of the tests are reported in Table B.

Table B Additive Shale Test N 0. Recovery 7 Concentra- (Percent) Type tion (lbs./

bbl.)

13. 0 16. 2 15. 5 25. 4 10 15. 3 15. 2 13. 7 Separau 2610. 17.2 (NH4)2SO4 1O Separan 2610. .02 16. 5 K01. 10 0. 25 30. 6 0. 5O 54. l 1. 00 78. 7 0. 25 14. 7 0. 5O 66. 6 1. 0O 80. 4 1. 00 71. 6 2. 00 78. 0 1. O0 76. 5 1. 00 68. 4 1. 00 76. 0 0. 50 48. 6 1. 00 18. 2 23 .rlo 1. 03 62.5 Acetic acid.. 50 24 Amine 220 l. 00 65. 5 Cone. HCL. .50 25 Ethomeen 8/12.. 1. Or) 26. 0 26 Ethomeen 8/12... 1. 00 58. 4 Acetic acid 5O In Table 13 the amines are ldentified principally by trademarks. Armac C 1s a mixture of amines derived from coconut acids and made water soluble by forming the acetate salts. Armac T is the same except the amines are derived from tallow acids. Intracol CA has been previously defined. Intracol 0AM is a methanol solution of Intracol 0A containing about 20 percent methanol. Intracol R is the same as Intracol 0 except that it is made from coconut oil rather than from oleic acid. Intracol O is the amine from which the acetate salt, Intracol 0A, is prepared. Aerosol C61 is an ethanolated alkyl guanidine amine complex. Nalquat G911 is a substituted imidazoline which has been quaternized by the addition of a hydroxy ethyl and a chlorobutyl group to the secondary nitrogen. Nalcamine G30 is a substituted imidazoline containing an alkyl and a hydroxy ethyl group. Amine 220 is a simple alkyl substitute imidazoline. Ethomeen S/ 12 is an oxyethylated alkyl amine derived from soy acids. Some of the amines are mixtures. Others are fairly pure compounds. When the term amine is used hereinafter it is intended to mean either a single amine or a mixture of amines.

In Table B test 1 shows that in the presence of water alone 87 percent of the shale disintegrated to such a degree that it passed through the 30 mesh screen. The 13 percent recovery figure is an average of many tests. These gave values which varied from a little over 10 to as high as 17, depending upon the nature of the particular shale sample tested. This same variability of shale samples should also be taken into consideration in comparing the effects of the various additives. Tests 2, 3, and 4 show the small effects of ammonium and potassium salts in decreasing the tendency of the shale to soften. Test 5 demonstrates the ineffectiveness of the low molecular Weight, organic, nitrogen-containing chemical, urea. Tests 6 and 7 show that Separan and diesel oil also have little effect by themselves. Tests 8 and 9 demonstrate that combinations of ammonium and potassium salts with Separan are also ineffective for this purpose. Tests 10 to 15, inclusive, not only prove the eifectiveness of two different types of high molecular weight amines in water-soluble form, but also provide evidence that the amines or their salts should be used in a concentration of at least about 0.5 pound per barrel if used alone. Later data will show that,

when used in combination with other ingredients, the concentration can be somewhat lower.

Test 16 shows that the amines derived from fallow are about as effective as those derived from coconut oil when used in the form of the water-soluble acetates. Test 17 demonstrates that the presence of methyl alcohol does not substantially affect the effectiveness of Intracol A so long as the concentration is increased to compensate for the presence of the alcohol. Test 18 shows that, due to the short hydrocarbon radicals in the amines derived from coconut oil and due to the plurality of amine groups in Intracol R, this material is sufiiciently water soluble to be effective in the absence of a salt-forming acid.

The amines in tests 19, 20 and 21 were also used in the form of the amine itself rather than its salt. In every case the chemical is a polyamine. This probably explains the effectiveness. Amine 220 tested in tests 22, 23 and 24 is also a polyamine, being quite similar to Nalcamine G-30. In this case, however, the amine definitely was not soluble to the extent of 1 pound per barrel of water. The poor results of test 22 indicate the amine was hardly soluble at all. The addition of either acetic acid or hydrochloric acid, however, resulted in the formation of a watersolublesalt which was quite effective. Ethomeen S/ 12 of tests 25 and 26 was another amine which was only slightly effective when used alone, but became much more effective when used as a water-soluble salt. While the amine itself is water dispersible, the degree of molecular dissociation in water apparently was not sufiicient in the absence of an acid to permit effective action by the amine.

Table C presents data on the compatibility of two amines with ammonium and potassium salts, with Separan 2610 and with oil. One amine, lntracol CA, has a linear polyamine group. The other, Nalcamine G30 has a cyclic polyamine group.

Table C Additive Shale Test No. Recovery Concentra- (Percent) Type tion (lbs./

bbl.)

Intracol 0A 0.5 0.5 (NH4)ZS O 10.0 Intracol 0A 0.5 (NH4)2SO4 10.0

Separan 2610. 0.02 Intracol OA 0. 5 (NHmS 0 10.0

Separan 261 0.02

' 1. 8 5 Nalcamiue G-30. 0. 5 6 Nalcamine 6-30. 0. 5 (NH-D2304 10. 0 7 Nalcamine G-30 0. 5 (NH4)2SO4 10.0

Separan 2610. 0.02 3 c. Nalcamine G-30 0.5 10.0

Test 1 in Table C should be compared to test 14 in Table B. The difference in results in due in part to variation in the properties of shale samples in the two tests. The difference also illustrates the erratic results which sometimes occur when an amount of amine near the minimum is used. Test 5 of Table C is identical to test 21 of Table B and is repeated simply for convenience of comparison. Tests 2 and 6 show that the amines are compatible with ammonium sulfate. Tests 3 and 7 demonstrate compatibility of the amines with a combination of ammonium sulfate and Separan. In addition, the combination effect of Intracol 0A, the linear polyamine, with Separan is to be noted. This is not observed with the cyclic amines. A further combination effect with oil is shown in tests 4 and 10 for the linear amine while test 8 shows that no such combination effect is observed in the case of the cyclic amine. Test 9 is included to show the compatibility of potassium salts with the other ingredients in the absence of oil and to show, by comparison to test 10, the combination effect of the oil.

EXAMPLE 3 The effects of the various additives on the loss of water to formations was determined by measuring the rate of flow of aqueous solutions of the additives through discs of sandstone. The discs were 0.5 inches thick and 2 inches in diameter. They were cut from the Nellie Bly sandstone which lies several feet above the Labette shale series and outcrops west of Tulsa, Oklahoma. A pressure difference of pounds was imposed across the discs. The time in seconds was recorded for successive 100 milliliter portions of the various solutions to flow through the discs. The results of tests are reported in Table D.

Table D Additive Water Rate, Seconds for 100 ml. to Flow Test N o. Water-l-Additivc Ooncen- Water Type tration Alone (lb/Dbl.) 1st 2nd 3rd Separan 26l0 0.02 1. 00 Separan 2610 0.02 3 {Nalquat G -11". 1. 00 Separan 2610.. 0.02 4 {Aerosol 0-61 1.00 Separan 2610 0.02 5 {Armac T 1. 00 Separan 2610 0.02 6 {Nalcamine G*30 1. 00 Separan 2010..."..- 0.02 7 {Intracol 0A--. 1.00 Separan 2610 0.02 Intracol GA. 0.06 8 Intracol CA. 0.25 Intracol OA. 0.50 Intracol 0A. 1. 00

The results of test 1 in Table D show the previously reported decrease in fluid loss provided by Separan 2610 alone. Test 8 shows the effects of our preferred amine salt, Intracol 0A, in various concentrations. It will be apparent from test 8 that, if the amine is used in the absence of Separan, the concentration should be at least about 0.5 pound per barrel of water if a substantial decrease in fluid loss is to be produced. Tests 2 to 7 dem onstrate the effectiveness of combinations of Separan 2610 with several amines. It will be apparent that this combination of additives is very effective in decreasing the loss of water to formations drilled.

EXAMPLE 4 To determine the effects of the amine and Separan on the permeability of oil-bearing sands, a test was run as described in Example 3 except that the core was first saturated with oil. Then, after the aqueous solution was forced through the core for a time, oil was caused to flow back through the core to simulate production of oil from a well drilled with the aqueous solution. Results of the test are reported in Table E.

once a formation is saturated with oil, the amine and Separan have little tendency to decrease the permeability.

EXAMPLE 5 Tests were conducted to compare the rate of corrosion of the water treated for shale drilling, with and without oil, to the corrosion rates of fresh water and brine. The results are presented in Table F. The rates of corrosion Were determined by measuring the change in conductance of a mild steel probe in the flowing solutions.

I able F Test Corrosion No. Water Tested Rate, Mils Per Year Fresh water 15. Brine (4% NaOl, 1% (321012, 0.5% MgCli) 18. 3 Water+0.5 lb. Intracol 0A, 0.02 lb. Separan 25. 6

2610, and 10 lb. (NH4)204 per barrel of water.

Same as test 3+0.21 gallon oil per barrel of water. 8. 8

The tests in Table F show that a corrosion problem exists when our combination of ammonium or potassium salt with an amine and Separan is used. The tests also show, however, that the use of a little oil with the combination decreases the corrosion rate to a value less than that caused by fresh water.

EXAMPLE 6 In view of the successful laboratory tests, the preferred shale drilling fluid was subjected to shallow well tests in which the performance of the solution was compared to that of water. The wells were drilled a few feet from the edge of a cliff which exposed from the top down 4 or feet of soil, 5 feet of hard sandstone, and 20 feet of Labette shale. The formations were not weathered since the excavation exposing the formations had been made recently. In wells drilled with plain water containing .02 pound of Separan 2610 per barrel of water, 500 gallons of make-up water were required. In these wells balling of cuttings and sloughing of shale into the hole occurred. In addition, on the cliff face adjacent to these wells the exposed shale became wet and sloughed. In wells drilled with the treated water, no such difliculties were encountered. Only about 1 extra barrel (42 gallons) of water was required in drilling these wells. No balling or sloughing occurred in the well. There was no evidence of water on the cliff face opposite these wells. The treated water contained 10 pounds of ammonium sulfate, 0.5 pound of Intracol GA, 0.02 pound of Separan, and 0.5 gallon of diesel oil per barrel of water. It will be apparent from these shallow well tests that the advantages appearing in the laboratory tests are realizable in actual well drilling operations.

When the results reported in the examples are studied, it becomes apparent that most high molecular weight amines can be used in combination with the ammonium and potassium salts to protect shales from the softening eifects of water. The only requirements seem to be that the amine be used in a water-soluble form and that it contain a hydrocarbon radical long enough to form a hydrophobic protective film over the shale surfaces. The first requirement can be easily met by forming a watersoluble salt such as the acetate or chloride if the amine itself is not sufliciently water soluble. In this connection, the term water-soluble amine or amine salt should be interpreted to mean a solubility of at least about 1 pound of amine or its salt per barrel of water. The second requirement can be met by use of amines having hydrocarbon radicals containing at least about 12 carbon atoms.

For really effective action, most amines should be used in concentrations of at least about 1 pound per barrel of water. Some beneficial effects are produced, however, by use of 0.5 pound or less per barrel. In the presence of Separan 2610 and oil it Willbe apparent that 0.5 pound per barrel of the linear polyamines such as Intracol 0A is more than adequate. Thus, when the combination of ingredients is used with this particular class of amines, the amine concentration can be reduced. At least about 0.4 pound per barrel of even the linear polyamines should be used, however, since the data in Tables B and C show the erratic behavior which may result from use of too little amine.

The concentration of Separan 2610 may be zero if desired since the amines alone provide considerable protection to the shale. The concentration of Separan should normally not exceed about 0.02 pound per barrel of water for economic reasons. Most of this additive is lost from the drilling fluid in a single cycle through the well. The material must, therefore, be added almost continuously. This explains the low concentration which is economically feasible. To obtain the combination effect with the linear polyamines, a concentration of at least about 0.005 pound per barrel should be used. This concentration of Separan will also produce an appreciable reduction in loss of water to the formations drilled.

Oil may also be omitted if desired. In view of the combination effect with other ingredients, its corrosion inhibiting ability, and other desirable properties such as its lubricating action, use of about 0.5 gallon of oil per barrel of water is preferred. At least about 0.1 gallon of oil per barrel of water should be added to obtain the combination effect. The oil may be ordinary crude petroleum oil available in the field. It is preferred, however, to use a refined petroleum fraction. such as diesel oil.

Throughout the foregoing description reference has been made to clear water, or water substantially free of solids. Both terms are generally used in the art to describe the type of drilling fluid to which our invention is applicable. Both terms, however, may be somewhat misleading. We have found that it is solids in the colloidal particle size range, that is, from about 1 to about millimicrons in maximum dimension, which decrease drilling rates. Solids which are in true solution, that is, below the colloidal range, and solids above the colloidal range have relatively little eflfect on drilling rates. It is also apparently the absence of colloids in the drilling fluid which is one of the principal causes for the tendency of shales to slough.

Water may appear clear, but may contain suflicient colloids such as starch, sodium carboxymethyl cellulose or the like to decrease drilling rates and shale sloughing. The term clear water is thus seen to be too broad. Water may appear to be very muddy and actually may contain many salts in solution and many solids dispersed as particles above the colloidal range. Such water certainly is not substantially free of solids, but it permits high drilling rates and usually presents problems of shale sloughing to which our invention is applicable. For these reasons, the term water substantially free of colloidally dispersed solids seems best to define the field to 11 which our invention is applicable. This term should be interpreted to mean water containing less than about 2 percent of solids in the colloidal particle size range.

We claim:

1. A drilling fluid comprising water substantially free of colloidally dispersed solids, containing in each 42-gallon barrel of water at least about 3 pounds of a salt selected from the group consisting of water-soluble ammonium and potassium salts and at least about 0.5 pounds of a water-soluble form of an amine having a hydrocarbon radical containing at least about 12 carbon atoms.

2. The drilling fluid of claim 1 in which said amine is a polyamine having the nitrogen atoms in a linear noncyclic configuration.

3. The drilling fluid of claim 1 in which said amine is in the form of the acetic acid salt of the oleic acid amide of polyethylene polyamine containing multiple amine groups.

4. The drilling fluid of claim 1 in which said salt is ammonium sulfate and said amine is a polyamine in which the nitrogen atoms are in a linear non-cyclic configuration.

5. A drilling fluid comprising water substantially free of colloidally dispersed solids, containing in each 42-gallon barrel of water at least about 3 pounds of a salt selected from the group consisting of water-soluble ammonium and potassium salts, at least about 0.4 pound of a water-soluble form of an amine having a hydrocarbon radical containing at least about 12 carbon atoms, at least about 0.005 pound of an acrylamide polymer hydrolyte having from about 10 to about 120 amide groups for each carboXyl group and having a viscosity of at least about 4 centipoises for a 0.5 percent by weight aqueous solution of said hydrolyte, and at least about 0.1 gallon of a mineral oil.

6. The drilling fluid of claim 5 in which said amine is a polyamine having the nitrogen atoms in a linear noncyclic configuration.

7. The method of drilling a well comprising circulating in said well in contact with formations containing hydratable shale, the composition of claim 5.

8. The method of claim 7 in which said amine is a polyamine having the nitrogen atoms in a linear noncyclic configuration. e

9. The method of claim 8 in which said salt is ammonium sulfate.

10. The method of drilling a well comprising circulating in said well in contact with formations containing hydratable shale, water substantially free of colloidally dispersed solids, containing in each 42-gallon barrel of water at least about 3 pounds of a salt selected from the group consisting of water-soluble ammonium and potassium salts and at least about 0.5 pound of a watersoluble form of an amine having a hydrocarbon radical containing at least about 12 carbon atoms.

11. The method of claim 10 in which said amine is a polyamine having the nitrogen atoms in a linear noncyclic configuration.

References Cited in the file of this patent UNITED STATES PATENTS 1,460,788 Carmen July 3, 1923 2,315,734 Ralston et al. Apr. 6, 1943 2,761,843 Brown Sept. 4, 1956 2,862,880 Clemens Dec. 2, 1958 2,873,251 Jones Feb. 10, 1959 2,894,907 Newcombe et al. July 14, 1959 2,960,464 Weiss et al. Nov. 15, 1960 FOREIGN PATENTS 760,653 Great Britain Nov. 7, 1956 799,621 Great Britain Aug. 13, 1958 OTHER REFERENCES McGhee: New Oil Emulsion Speeds West Texas Drilling, The Oil and Gas Journal, Aug. 13, 1956, pp. -112.

Burdyn et al.: That New Drilling Fluid for Hot Holes, The Oil and Gas Journal, Sept. 10, 1956, pp. 104107.

Mallory: How Low Solids Muds Can Cut Drilling Costs, The Petroleum Engineer, April 1957, pp. B21, B22, B23 and B24. 

1. A DRILLING FLUID COMPRISING WATER SUBSTANTIALLY FREE FO COLLIODALLY DISPERSED SOLIDS, CONTAINING IN EACH 42-GALLON BARREL OF WATER AT LEAST ABOUT 3 POUNDS OF A SALT SELECTED FROM THE GROUP CONSISTING OF WATER-SOLUBLE AMMONIUM AND POTASSIUM SALTS AND AT LEAST ABOUT 0.5 POUNDS OF A WATER-SOLUBLE FORM OF AN AMINE HAVING A HYDROCARBON RADICAL CONTAINING AT LEAST ABOUT 12 CARBON ATOMS. 